Crude oil refineries include an atmospheric pressure pipestill (APS) which fractionates the whole crude oil into various product fractions of different volatility, including gasoline, fuel oil, gas oil, and others. The lower boiling fractions, including naphtha, from which gasoline is derived, are recovered from the overhead fraction. The fractions with intermediate volatility are withdrawn from the tower as sidestreams. Sidestream products include kerosene, jet fuel, diesel fuel, and gas oil. The higher up on the column the sidestream is withdrawn, the more volatile the product. The heaviest components are withdrawn in the tower bottoms stream.
FIG. 1 is a simplified process flow diagram of a typical crude oil atmospheric pipestill unit. The crude is preheated in preheat exchangers against overhead product and then heated up to abut 500.degree. F. to 700.degree. F. in a direct-fired furnace. The feed is then flashed into the atmospheric pipestill which operates at a pressure between one and three atmospheres gauge pressure. Overhead tower temperature ranges typically from 200.degree. F. to 350.degree. F. FIG. 1 shows a two-stage overhead condenser system; alternative systems use one condenser stage. The overhead and sidestream products are cooled and condensed and sent to other units to be processed into final products. The bottoms stream goes to a second distillation tower (not shown) that operates under a vacuum and distills more light products out of the APS bottoms. Steam is added to the bottom of the tower to promote stripping of light products from the bottoms. Also, water is added to the top of the column to wash away soluble salts which often accumulate in the top trays and overhead components. The stripping steam and wash water coming into the system are substantial; the overhead naphtha gas stream coming off the top of the tower typically contains 20 to 40 mole % water.
The corrosion that is the subject of this invention occurs in the overhead components of the atmospheric pipestill which include the top tower trays, the piping that comes off the top of the tower and the reflux lines, the heat exchangers, the condensers and rundown lines, and the distillate drums where the condensed overhead stream is separated into liquid naphtha product and reflux. Materials commonly used in APS overhead trays and components include carbon steel, Monel 400 and 410 stainless steel. Corrosion damage can be very severe, including metal loss severe enough to cause leakage to the external environment and internal heat exchanger leaks, plugging of trays and other internals which interfere with tower operation and control and impair energy efficiency. In addition, corrosion in the APS can cause operating problems in downstream units. Because of the severity of the corrosion, even one day of uncontrolled corrosion can have serious consequences. Corrosion in the overhead exchangers is the major concern.
Corrosion in the overhead system is caused by hydrogen chloride produced by hydrolysis of chloride salts found in crude oil. Crude oils contain salts dissolved in water entrained from the production well and from saltwater picked up during tanker shipment. Generally, the chloride salts are sodium chloride, magnesium chloride, and calcium chloride. Depending on the source of the saltwater, the amount of each salt in the crude can vary considerably. Sodium chloride is stable and does not hydrolyze significantly in the atmospheric crude tower system. HCl is released when MgCl.sub.2 and CaCl.sub.2 are hydrolyzed by water present in crude oil: EQU MgCl.sub.2 +H.sub.2 O=2HCl=MgO EQU CaCl.sub.2 +H.sub.2 O=2HCl=CaO
The chloride salts begin to hydrolyze at temperatures in the range of 350.degree. F. to 450.degree. F., which occur in the preheat exchangers.
The HCl produced in the preheat system does not cause corrosion there because there is no liquid water present. The HCl, however, goes through the pipestill and passes into the overhead gas.
Temperature decreases moving up the tower and into the overhead system. At some point, temperature falls below the dewpoint temperature of the process gas and water condenses on the equipment surfaces in a thin film. This point is called the "initial condensation point" or "ICP." Water continues to condense as the process gas moves downstream and is further cooled. The overhead gas is totally condensed in the overhead condensers, is accumulated in a condensate drum, and is removed from the bottom boot of the condensate drum. Operators usually maintain the temperature at the top of the tower at least 30.degree. F. to 40.degree. F. above the water dewpoint to avoid corrosion in the top trays. The trend, however, is to reduce tower top temperature to improve recovery of naphtha, and this drives the dewpoint down into the tower. Accordingly, the water dewpoint usually occurs in the overhead system, but it can occur within the distillation tower if the composition of the process streams and tower operating conditions combine to raise the dewpoint above the top tower temperature. Spot or "shock condensation" can occur upstream of the ICP if there are cold spots on upstream surfaces where, for example, insulation is worn and the tower shell is exposed to cold wet weather or at cold spots on heat exchanger tubes in the condensers. Accordingly, the locations where condensation initially occurs are uncertain and changeable as operating and ambient conditions change.
The ICP and shock condensation points are important because that is where chloride concentration is highest and pH lowest. Initial condensates, if untreated, exhibit pH's as low as one or even fractional pH's, and the danger of catastrophic corrosion at these points is great. Corrosion by acidic chloride condensates is driven by the hydrogen ion concentration (pH) via the reaction: EQU Fe+2HCl=FeCl.sub.2 (soluble)+H.sub.2
Hydrogen sulfide, which is formed in the pipestill from organic sulfur compounds in crude oil, also dissolves in water condensate and accelerates acidic chloride corrosion. Although the source of the corrosive attack is HCl, the product of corrosion is iron sulfide, not iron chloride. Iron sulfide is precipitated by the reaction between H.sub.2 S and soluble iron chlorides from the corrosion reaction between HCl and the steel equipment, thus liberating additional HCl. EQU FeCl.sub.2 +H.sub.2 S=FeS+2HCl
Note that the HCl is regenerated by the H.sub.2 S. Hydrochloric acid thus acts as a catalyst for formation of iron sulfide, and is not consumed.
The APS streams also contain low molecular weight carboxylic acids (acetic, propionic, butyric acids) which increase corrosion at the ICP and subsequent condensation zone.
The water coming overhead from the tower is totally condensed in the overhead exchangers and is accumulated in the condensate drum. The bulk water condensate contains chlorides, sulfides, and ammonia, and is mildly corrosive. Experience indicates that bulk water condensate should be maintained in the pH range of about 5 to 6.5 to minimize corrosion in the system. pH in the bulk condensate is controlled by adding a neutralizer, such as ammonia, to the overhead system.
In addition to being subject to severe corrosion at the ICP and points of shock condensation, APS systems are also vulnerable to severe corrosion upstream of the ICP where ammonium chloride precipitates as a solid out of the gas phase onto internal surfaces. Ammonium chloride is formed in the system by the reaction between ammonia and HCl. Ammonia comes into the pipestill in the incoming crude oil and other incoming process streams, and is often intentionally added to neutralize HCl in the overhead bulk sour water condensate. At equilibrium, the partial pressure of ammonium chloride over the internal surface on which ammonium chloride has deposited equals the vapor pressure of ammonium chloride at the temperature of the internal surface. FIG. 3 is a graph of vapor pressure of ammonium chloride versus temperature. If the partial pressure of ammonium chloride above the internal surface exceeds the vapor/equilibrium pressure, then ammonium chloride will precipitate on the surface and accumulate.
Ammonium chloride deposits are hygroscopic and, when exposed to wet process gas streams flowing by, absorb moisture, forming a wet paste with a pH of about 3.5, which is a highly corrosive enviromnment. Ammonium chloride deposits are only a problem if they form above the water dewpoint. If they form below the dewpoint where water is condensing profusely along with the ammonium chloride, then the deposits will be washed away. But, if ammo nium chloride condenses above the dewpoint and water is not condensing on these surfaces, ammonium chloride deposits will not be washed away by water and the deposits will build up.
APS corrosion problems are on the increase. The increased corrosion is attributed to several causes. Salt content of crude oils now being run in refineries have increased, generating more chlorides. Also, crudes are heavier, which makes them harder to desalt. Ammonia concentrations in pipestills have risen because of refinery operating changes in other units. Also, refiners are running lower tower top temperatures to increase yields of profitable distillate fuels, such as jet fuel, and also to raise energy efficiency of the operation. Reducing top temperature often brings the water dewpoint upstream from the overhead equipment into the tower.
The first defense against overhead corrosion is crude oil desalting. A desalter is shown in the flow plan of FIG. 1. In the desalter, crude is mixed with about 5% water, which dissolves the salt. The salty water is separated from the crude and discarded. However, oil/water emulsions form that are difficult to break. Chemical demulsifiers are added to break the emulsion. Electrical devises which charge the water drops to enhance separation are also used. Up to about 90% of the salt can be removed with a single stage of water washing and separation. Salt removal effectiveness depends on the nature of the crude. Heavier oils are more difficult to desalt than light crudes. A second wash state is commonly used to remove additional salt.
Caustic (NaOH) is commonly injected into the crude downstream of the desalter to reduce chlorides in the pipestill overhead system. The caustic reacts with the magnesium and calcium chloride to form sodium chloride, which is more thermally stable and so will not hydrolyze. However, caustic treat must be limited since caustic causes furnace coking and induces operating problems in downstream units. New catalysts being used in downstream units in response to environmental control demands being imposed on refineries are poisoned by caustic. In most instances, it is impractical to remove enough salt with desalters and/or caustic addition to completely eliminate HCl corrosion. Moreover, operating upsets in the pretreat systems occur, which periodically introduce large doses of chlorides.
Accordingly, chloride neutralizers are added to the APS system to inhibit corrosion. The most common neutralizer is ammonia. It can be added as ammonia gas or as an aqueous solution usually into the overhead lines between the pipestill and the overhead condensers. ammonia is effective for increasing the pH of the overhead bulk water condensate to within a safe pH range, which is abut 5.5 to 6.5. But, ammonia does not neutralize condensate acidity at the ICP and shockpoint environs where corrosion is most virulent. This is because ammonia is volatile and ammonium chloride unstable in the water phase at ICP and shockpoint temperatures.
These concepts can be visualized by referring to FIG. 2, which is a graph of temperature versus pH of condensate for a typical APS system. The pH at the initial point of condensation which, in this example, occurs at 230.degree. F., is below 1. pH rises to about 4 moving downstream along the curve left to right to 180.degree. F. where the water is totally condensed. Obviously, this situation is unacceptable since the system internals will experience catastrophic corrosion at the low pH's indicated.
Curve II is for a system protected with ammonia. Note that ammonia protects the system well upstream of the zone of initial condensation, but provides no pH elevation at the virulent zone of initial condensation.
Curve III is the pH curve required to adequately protect the system. Note that the pH is uniformly elevated into the corrosion safe 5 to 6 pH range across the entire condensation zone.
Current commercial practice to protect APS units from corrosion is to inject organic amines into the APS overhead system. The amines used are volatile, so they appear in the gas phase upstream of the ICP where they react with some of the HCl in the gas stream before the HCl reaches the condensation zone. However, there may not be sufficient time and contact in the gas phase to neutralize all the HCl upstream of the condensation point. Accordingly, some of the HCl must be neutralized in the aqueous solution after it is absorbed by the condensate water phase.
Suitable neutralization amines include morpholine, methoxypropylamine, ethylenediamine, monoethanolamine, and dimethylethanolamine. APS overhead neutralizing amines are usually added as aqueous solutions, typically about 50% water. The most common injection points are in the overhead lines between the pipestill and the overhead exchangers, the sidestream inlets to the tower, and directly to the crude oil coming into the tower. Common practice is to control the neutralizer addition rate to maintain the pH of bulk water condensate in the separator drums to between 5.5 and 6.5, and preferably 5.5 to 6.0. If the proper amines are selected, adequate pH elevation is achieved over the entire condensation zone when the pH of the bulk condensate is maintained over 5.5.
Filming inhibitors are usually injected into the overhead system to further reduce corrosion in the upstream sections of the overhead system. They are proprietary formulations, usually oil soluble, which protect equipment by forming a barrier on the steel surface. Film inhibitors are effective in the downstream sections of the condencing zone where chloride concentrations are moderate, but are not effective at ICP and shock points.
A disadvantage of using amines to control corrosion in condensing systems containing chlorides is that the amines react with chlorides to form hydrochloride salts which deposit on internal surfaces. The salts deposit on surfaces at temperatures above the water dewpoint, upstream of the condensation zone, often in the top trays of the system tower. The salt deposits are hygroscopic and absorb moisture from the process gas to form highly corrosive viscous fluid or paste which induce underdeposit corrosion.
Amine salts are not a problem if they deposit in the condensation zone because they are continuously washed away by condensate. Some operators mitigate the problem by periodically washing the overhead system with water to remove deposits.
Instances of salt deposition above the dewpoint in pipestills are increasing because refineries are running heavier and dirtier crudes, which generate larger amounts of chlorides and, to protect their units, operators are increasing neutralizer amine treat rates. Ammonium chloride deposition above the dewpoint is also increasing because ammonia in crude is increasing. Accordingly, there is a need in the refining industry for new technology to inhibit corrosion in wet hydrocarbon condensing systems containing chlorides which does not compound the problem by inducing troublesome salt deposits above the dewpoint. The present invention is a novel process which accomplishes this objective.
Corrosion control in crude distillation units is discussed in two papers which were presented to the National Association of Corrosion Engineers: Rue, J. R. and Naeger, D. P., "Advances in Crude Unit Corrosion Control," Corrosion '87, Paper No. 199, National Association of Corrosion Engineers, Houston, Tex.:, and Rue, J. R., and Naeger, D. P., "Cold Tower Aqueous Corrosion: Causes and Control," Paper No. 211, National Association of Corrosion Engineers, Corrosion '90, Las Vegas, Nev. The papers discuss the amine salt deposition problem, which is the focus of the present invention, but the authors advocate techniques which minimize and suppress chloride hydrolysis to solve the problem.
The amine salt deposition problem is addressed in U.S. Pat. No. 5,211,840, which teaches that amine salt deposition can be avoided by using weak base amines, those having pKa between 5 and 8. The inventors discovered that hydrochloride salts of weak amines have less propensity to deposit on tower internals than salts of strong amines and ammonium chloride. The patent says the amines may be added to the distillation unit at any point in the overhead system prior to the location where the condensate forms.
Specifically, the patent teaches:
that it is necessary to add a sufficient amount of the neutralizing amine compound to neutralize the acidic corrosion causing species. It is desirable that the neutralizing amine be capable of raising the pH of the initial condensate to 4.0 or greater. The amount of neutralizing amine compound required to achieve this objective is an amount sufficient to maintain a concentration of between 0.1 and 1,000 ppm. based on the total overhead volume. The precise neutralizing amount will vary depending upon the concentration of chlorides or other corrosive species. PA1 blending a minor amount of highly basic amine with a low pka amine. These blends would be advantageous to use in systems where a sub-neutralizing quantity of highly basic amine can be used without causing above the water dewpoint corrosion and/or fouling problems. PA1 that certain amines having the following formula corresponding to Formula 1 below: EQU R--O--(CH.sub.2)nNH.sub.2 Formula 1
The patent also teaches:
The patent cites 4-picoline and 3-picoline as examples of low pka amines, and methoxypropylamine and ethanolamine as highly basic amines. The patent defines minor amounts to be less than 20% of treatment.
The amine salt deposition problem is addressed in U.S. Pat. No. 4,430,196, which teaches the use of a member or members selected from the group of dimethylaminoethanol and dimethylisopropanolamine.
The amine salt deposition problem is also addressed in U.S. Pat. No. 4,806,229, which teaches:
wherein n is 2 or 3 and R is a lower alkyl radical of not more than 4 carbon atoms, when added to a crude oil charge or at various other points in the system, effectively eliminates and/or controls corrosion that ordinarily occurs at the point of initial condensation of water vapors within or leaving the distilling unit. Illustrative of compounds falling within Formula 1 are methoxypropylamine, ethoxypropylamine, methoxyethylamine, and the like. The most preferred compound is methoxypropylamine.
State of the art techniques and equipment for injecting and controlling addition of neutralizing agents to the APS system and other refinery distillation towers are described in U.S. Pat. No. 5,302,253, which is incorporated herein by reference. In one embodiment of the disclosure, the pH of condensate removed from the tower system is continuously measured with a standard pH electrode. The pH signal is sent to a controller, which compares it with the pH setpoint, and the controller throttles the pumping rate of the amine pump used to inject neutralizer into the APS system to bring the pH of the bulk condensate reading to the setpoint. Preferably, the condensate is bulk water condensate taken from the overhead accumulator drum water boot, but condensate can be removed from some intermediate condensation point in the tower overhead system. A corrosion safe range for bulk water condensate pH is typically 5 to 6.5.
U.S. Pat. Nos. 4,335,072 and 4,599,217 describe devices which attach to the treated system and monitor corrosion rate and treatment. The devices are termed "Overhead Corrosion Simulators" ("OCS"). These patents are incorporated herein by Reference. An Overhead Corrosion Simulator is a small condenser heat exchanger cooled with flowing cooling water which is installed onto the pipestill overhead system such that it withdraws a small overhead gas slipstream from the pipestill overhead. The slipstream is withdrawn from a point sufficiently upstream where the tower temperature is above the initial point of water condensation so that no water condensation has yet occurred. The OCS cools the overhead stream in small temperature increments from initial condensation through total condensation. The condensate at each stage of cooling is continuously collected and rate of corrosion and/or pH are continually monitored using conventional instrumentation techniques. Using the OCS, corrosion rates and pH, at each point in the system where water condensation is occurring, are simulated and continually monitored and conditions at the all important point of initial condensation continually observed even if the point shifts upstream or downstream in the APS overhead system.
Various amines are known for the treatment of hydrocarbon streams. For example, a process for substantially neutralizing the volatile acid gases and water present in the condensate of a distilling petroleum product, which comprises treating the distilling product prior to the condensation thereof with at least one amine in U.S. Pat. No. 4,806,229. A corrosion control method utilizing methoxypropylamine in petrochemical process units is disclosed in U.S. Pat. No.4,229,284. A method for neutralizing acidic components in petroleum refining units utilizing an alkoxyalkylamine is disclosed in U.S. Pat. No. 4,062,764. The use of at least one neutralizing amine for the prevention of fouling caused by amine chloride salt deposits is disclosed in U.S. Pat. No. 5,211,840. Certain amines as neutralizing agents in petroleum refining units are disclosed in U.S. Pat. No.4,430,196 and 3,779,905. Additionally, the use of2-amino-1-methoxypropane as a neutralizing amine in refinery processes is disclosed in U.S. Pat. No. 5,641,396. Though certain amines or blends have been disclosed, there remains a need in the refining industry for new technology for more efficiently inhibiting corrosion in wet hydrocarbon condensing systems containing chlorides while not compounding the problem by inducing troublesome salt deposits above the dewpoint. The present invention represents three novel blends which accomplish this objective.